1. Technical Field
Methods and apparatuses are disclosed for generating borehole seismic surveys. More specifically, this disclosure relates to the generation of three-dimensional (3D) vertical seismic profiles (VSP) in a time-efficient and cost-efficient manner. More particularly, instead of firing the seismic source at regular and predetermined intervals and/or predetermined locations, this disclosure discloses methods and apparatuses for real-time reflection point density mapping of the seismic data after one or more seismic source firings for evaluating the sufficiency of the data in one area or bin before subsequent source firings are carried out in another area or bin. The actual coordinates or locations of the source firings are more accurately accounted for using a GPS system. The disclosed methods enable 3D VSPs to be produced faster, more efficiently and with enhanced data quality.
2. Description of the Related Art
Geophysical mapping techniques for determining subsurface formation structures include, for example, seismic surveying, magnetotelluric surveying and controlled source electromagnetic surveying, among others. Generally, a variety of different seismic surveying techniques may be used in performing seismic exploration on land and in marine environments.
Seismic energy travels downwardly from one or more seismic sources and is reflected from acoustic impedance boundaries below the surface of the earth. The seismic sources are typically disposed on land or suspended from a boat during firing. The reflected seismic energy is detected at the sensors or receivers disposed on land, the floor of an ocean or other body of water or, inside a borehole. Various techniques are known in the art for determining the structure of the subsurface formations below and/or adjacent to the receivers from recordings of the signals corresponding to the reflected seismic energy. Other techniques known in the art provide estimates of fluid content in porous subsurface formations from characteristics of the reflected seismic energy such as its phase and/or amplitude.
In recent years, offshore hydrocarbon exploration has been occurring at increasingly deeper depths of water. As the water depths increase and the wells that are drilled lengthen, recovery of hydrocarbons from subsurface formations becomes increasingly difficult and complex. To facilitate hydrocarbon recovery, sophisticated seismic surveys such as vertical seismic profiles (VSPs), are being used to provide detailed characterizations of subsurface formations.
VSPs are measurements made in a wellbore using acoustic receivers inside the borehole and seismic sources at the surface. VSPs can vary in the number and location of seismic sources and receivers, and how the receivers and sources are deployed. Conventional VSPs are generated from use of a surface seismic source, which is commonly a vibrator or dynamite shot-holes on land, or an air-gun in marine environments, and a receiver array disposed in the borehole. More recent techniques involve the use of a seismic source placed at the ocean floor or suspended from a boat and spaced away from the borehole.
VSPs are used for correlation between a surface seismic image and wireline logging data. VSPs can be used to tie surface seismic data to well data, providing a useful tie to measured depths. VSPs enable the conversion of seismic data to zero-phase data, and enable one to distinguish between primary reflections and multiple reflections. In addition, a VSP is often used for analysis of portions of a formation ahead of the drill bit.
Check-shot surveys are similar to VSPs in that acoustic receivers are placed in the borehole and a surface source is used to generate an acoustic signal. However, a VSP is more detailed than a check-shot survey as VSP receivers are typically more closely spaced than those in a check-shot survey. While check-shot surveys may include receiver intervals hundreds of meters apart, the Schlumberger Versatile Seismic Imager™ (VSI™) tool includes up to 40 receivers spaced from 5 to 30 meters apart for a tool length of up to 1200 meters. Further, a VSP uses the reflected energy contained in the recorded trace at each receiver position as well as the first direct path from source to receiver, while the check-shot survey uses only the direct path travel time.
Three dimensional (3D) VSPs are available through the use of offset operations. Offset operations usually include a seismic source having one to twelve or more air guns, a remote and movable installation, such as a boat or land vehicle, that moves to a fixed offset position from the wellbore, along a predetermined “walkaway line” or path away from the wellbore, or along a predetermined spiral path away from the wellbore. For 3D-VSP sources towed behind a boat, three to 12 air guns are typically used.
Although 3D VSPs are a valuable information tool for analyzing subsurface formations, acquisition of 3D VSP data by way of seismic waves that are generated by a surface source or seabed source is problematic. First, the time required to acquire an effective 3D VSP can range from a few to several days, resulting in large and costly seismic datasets and substantial costs in terms of rig time. Because of the time and expense involved in acquiring 3D VSPs, it is customary to acquire data outside of the important zones of interest as a safeguard against producing a 3D VSP with missing data, which results in additional costs and rig time. Further, because of the time involved in acquiring 3D VSPs, surveys can be cut short for weather reasons or equipment malfunction, which can result in incomplete data sets. Finally, data acquired from source firings at various locations in the survey may be poor, compromised and/or invalid due to various conditions beyond the control of the operator. Because data problems may not be discovered until after the survey is complete and during subsequent data processing, it is sometimes necessary to go back to the wellsite and perform additional source firings in order to satisfactorily complete a VSP.
A common data processing technique designed to avoid going back to the wellsite and performing additional source firings is the concept of “binning,” which involves the duplicitous use of data from one area or “bin” of a target reflector in an area or bin of the target reflector where the data is insufficient. Currently available binning techniques will now be described in connection with FIGS. 7-12. At the outset, the concept of binning relates to the subdivision of a survey area of a target reflector 24 into a plurality of individual contiguous bins 40. Turning first to FIG. 7, a bin 40 is illustrated which includes six common image points (CIPs) 41 or a “fold” of six. The CIPs 41 of a bin 40 may be stacked together to provide a stacked trace at the center of the bin 40. In the example shown in FIG. 7, the six CIPs may each be from a different offset group. However, having a fold of six for each bin 40 of a survey may be unlikely and it is common for many bins 40 of a survey to have low folds or irregularities. Because of fold variations in the various bins 40 of a survey, the effectiveness of stacking is reduced. To provide a high degree of consistency in the folds of the various bins 40, binning is carried out.
For example, referring to FIG. 8, the survey was divided into twenty different bins 40. A closer inspection of the bins 40 of FIG. 8 reveals that the folds of the bins 40 varies from three (see the bin 40a disposed in the middle row, second column from the left) to seven (see, e.g., the bins disposed in all four corners). Without some sort of intervention, subsequent processes such as velocity analysis and stacking will be substantially less effective, with irregular offset distributions and cross-line scattering of image points within bins like the bin shown at 40a, 40b in FIG. 8.
FIG. 9 illustrates another binning technique wherein bins 40a, 40b, each with folds of three and four respectively, are expended by a fixed amount in opposite directions, in this example 25% in each direction, so as to encompass an additional three and two CIPs respectively. More specifically, the bin 40a is expanded by the fixed amount of 25% to encompass two CIPs from the bin 40c and by another fixed amount of 25% to encompass a single CIP from the bin 40d as shown in FIG. 9. Further, the bin 40b is expanded by fixed amount of 25% to encompass a single CIP from the bin 40c and by another fixed amount of 25% to encompass a single CIP from the bin 40f. After the fixed or overlap binning process is carried out as illustrated in FIG. 9, the bin 40a, originally with a fold of only three, now has a fold of six. Further, the bin 40b, originally with a fold of only four, now has a fold of six as well.
Turning to FIG. 10, instead of expanding the bins 40a, 40b by fixed amounts, the bins 40a, 40b are expanded by amounts sufficient to increase their respective folds to six. Thus, the bins 40a, 40b are expended by flexible or elastic amounts so as to increase their respective folds to a predetermined level of six. Turning to FIG. 11, three bins 40g, 40h, 40i of equal size are illustrated. The center bin 40g includes only eleven CIPs or fold of eleven while the outer bins 40h and 40i have folds of 42 and 46 respectively. To increase the fold of the center bin 40g, the bin 40g is expanded by 40% into the bin 40h and by 40% into the bin 40i to increase the fold of the bin 40g to 49 as shown in FIG. 11. Similarly, turning to FIG. 12, three bins 40j, 40k, 40l of equal size are illustrated. The center bin 40j includes only sixteen CIPs or fold of sixteen while the outer bins 40k and 40l have folds of 42 and 46 respectively. To increase the fold of the center bin 40j, the bin 40j is expanded by 20% into the bin 40k and by 20% into the bin 40l to increase the fold of the bin 40j to 36 as shown in FIG. 12. As shown above in FIGS. 9-12, with both overlap (fixed %) and elastic (variable) binning, the fold of a bin is artificially increased. Because a particular bin may contain more than one common image point (CIP) within a given offset group, redundancy editing may be required.
However, all of these binning techniques described in FIGS. 7-12 rely upon using data from adjacent bins to provide a sufficient number of CIPs in a bin where the fold is deficient. No new data is created and no attempt is made at obtaining additional data for the deficient bin. Further, each of the binning techniques illustrated in FIGS. 7-12 are post acquisition, and cannot readily be performed in real time. Further, the binning techniques of FIGS. 7-12 assume that reflection point data is available from the adjacent bins. However, this assumption is not always true and cannot be guaranteed during the survey. If data from an adjacent bin is not available, the operator will not find out until after the survey is complete and the equipment has been withdrawn. With marine 3D-VSP surveys acquired during rough sea conditions, control of the source location may be compromised, leading to uneven reflection point density coverage in the subsurface. When using the binning techniques of FIGS. 7-12, this type of problem may result in oversized bins that seek to combine reflection points that are widely separated, thereby causing undesirable smearing of the data. If the impact of such acquisition problems on the true reflection point density at the target could be estimated in real-time, then it would be possible to adjust the acquisition effort to avoid such problems occurring.
Thus, more cost efficient and time efficient methods for acquiring VSPs are needed that provide real time assurances that the seismic data is of a high quality and that provides the operator with an indication as to when a survey may be stopped.